Method and apparatus of distributed systems for extending reach in oilfield applications

ABSTRACT

Apparatus and a method for delivering a rod in a cylinder including propagating a rod in a cylinder along the interior of the cylinder, and introducing a motion in an orientation orthogonal to a length of the rod, wherein the motion comprises multiple motion sources along the length of the rod, and wherein the multiple motion sources comprise a control system that controls at least one of the motion sources. An apparatus and method for delivering a rod in a cylinder including a cylinder comprising a deviated portion, a rod comprising a length within the cylinder, multiple motion sources positioned along the length of the rod, and a control system in communication with at least one of the motion sources, wherein the control system controls the location of frictional contact between the rod and cylinder over time.

FIELD

Embodiments relate to methods and apparatus for moving a rod through acylinder. Some embodiments relate to coiled tubing for oil fieldservices and some embodiments relate to maintaining pipes containinghydrocarbons.

BACKGROUND

Helical buckling thwarts the efforts of many who aspire to resolvewellbore or pipe problems with mechanical equipment that utilizes along, flexible rod or tube. Coiled tubing operations (CT) especiallyencounter helical buckling problems when the tubing is of extendedlength in deviated wellbores. This problem often limits the extent ofreach in extended reach coiled tubing operations. Coiled tubing mayexperience helical buckling as the tubing travels through high frictionregions of a wellbore or through horizontal regions of a wellbore. Inconventional coiled tubing operations, the tubing is translated alongthe borehole either via gravity or via an injector pushing from thesurface. For an extended reach horizontal wellbore, an axial compressiveload will build up along the length of the coiled tubing due tofrictional interactions between the coiled tubing and the borehole wall.A typical axial load as a function of measured depth is plotted inFIG. 1. This wellbore has a 4000 foot vertical section, a 600 foot, 15degree per 100 foot dogleg from vertical to horizontal, and thencontinues horizontal until the end.

If the horizontal section of the wellbore is sufficiently long, theaxial compressive load will be large enough to cause the coiled tubingto buckle. The first buckling mode is referred to as “sinusoidalbuckling”—in this mode, the coiled tubing snakes along the bottom of theborehole with curvature in alternating senses. This is a fairly benignbuckling mode, in the sense that neither the internal stresses norfrictional loads increase significantly. As the axial compressive loadcontinues to increase, the coiled tubing will buckle in a secondbuckling mode. This buckling mode is called “helical buckling”—this modeconsists of the coiled tubing spiraling or wrapping along the boreholewall. This buckling mode can have quite severe consequences—once thecoiled tubing begins to buckle helically, the normal force exerted bythe borehole wall on the tubing increases very quickly. This causes aproportional increase in frictional loading, which in turn creates anincrease in axial compressive load. Once helically buckling hasinitiated, the axial compressive load increases very quickly to a levelsuch that the tubing can no longer be pushed into the whole. Thiscondition is termed “lock-up.” A plot of axial load as a function ofmeasured depth for a coiled tubing which is almost in a locked up stateis shown in FIG. 2.

Coiled tubing operations employ several techniques for maximizing thedepth of penetration in extended reach wells. Vibrators are used inconjunction with CT to increase the depth of penetration in extendedreach wells. These vibrators are made up to the bottomhole assembly(BHA) connected at the end of the CT string and are normally activatedby pumping fluid through them. The oscillating action caused by thevibrator results in reduced drag forces on the pipe as it is pushed intothe wellbore from surface. One of the more effective solutions uses avibrator as part of the bottomhole assembly (BHA). The oscillationscaused by the vibrator reduce the excessive drag on the CT string inhigh angle wellbore trajectories. This reduction in drag often delaysthe onset of helical buckling. Effectively, this drag reduction has beenfound to be equivalent to as much as 30% of the friction coefficientbetween the wellbore wall and the CT. Thus, drag force reductionincreases the CT's ability to go further in an extended reach well.However, depending on the wellbore configuration and the CT stringcharacteristics, as well as the vibrator's amplitude and frequency ofthe oscillations produced, the position of the vibrator at the terminalend of the BHA may not be effective to allow well total depth (or targetdepth) to be reached.

When a CT string goes into lockup mode, the entire string length is notcompletely helically-buckled. There are typically one or two locationsin the wellbore where the CT is at a critical state, depending onseveral physical factors, including wellbore/completion design, CTstring characteristics, etc. Lock-up developing in these one or twocritical locations is sufficient to prevent the CT from advancingfurther into the wellbore. The location is typically either near surfacebelow the wellhead for most high angle wells or near the heel of a longhorizontal well or both. These locations can be identified prior toactual insertion of the CT into the well through analysis using a forcemodeling software such as CoilCADE™, a commercially available productavailable from Schlumberger Technology Corporation of Sugar Land, Tex.

Similarly, pipe used to connect the output of wellbores in oil fieldsincluding offshore operations may require maintenance to remove residueand/or improve flow. Such systems exercise flexible tubing equipmentthat experiences similar buckling along the length of the tubing whenequipment is introduced to service the pipelines.

SUMMARY

Embodiments relate to an apparatus and a method for delivering a rod ina cylinder including propagating a rod in a cylinder along the interiorof the cylinder, and introducing a motion in an orientation of at leastone of the followings (orthogonal, parallel to or rotational) to alength of the rod, wherein the motion comprises multiple motion sourcesalong the length of the rod, and wherein the multiple motion sourcescomprise a control system that controls at least one of the motionsources. Embodiments relate to an apparatus and method for delivering arod in a cylinder including a cylinder comprising a deviated portion, arod comprising a length within the cylinder, multiple motion sourcespositioned along the length of the rod, and a control system incommunication with at least one of the motion sources, wherein thecontrol system controls the location and orientation of frictionalcontact between the rod and cylinder over time.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments are further explained in the detailed description thatfollows, in reference to the noted plurality of drawings by way ofnon-limiting examples of exemplary embodiments of the present invention.The patent or application file contains at least one drawing executed incolor. Copies of this patent or patent application publication withcolor drawing will be provided by the Office upon request and payment ofthe necessary fee.

FIG. 1 is a plot of axial load as a function of measured depth of theprior art.

FIG. 2 is a plot of axial stress as a function of measured depth of theprior art.

FIG. 3 is a schematic diagram of a rod comprising multiple sections anddevices distributed across the length of the rod.

FIG. 4 is a schematic diagram of a coiled tubing assembly.

FIGS. 5A, 5B and 5C are renditions and a photo of tubing connectors.

FIG. 6 is a sectional view of a schematic of a Moineau vibrator device.

FIG. 7 is a sectional view of a schematic of a tractor.

FIG. 8 is a plot of pump rate and pressure as a function of time forvibration and operation modes.

DETAILED DESCRIPTION

Generally, coiled tubing is selected for its ability to coil on a reelfor transport at the surface, to retain some rigidity and integrity asit travels through a pipe or wellbore, to convey material orinformation, and/or to perform a specialized service at the terminal endof the tubing. Further, coiled tubing is often used in harsh conditionswhere design parameters must also encompass transport, environmentalstewardship, and sturdy, rugged construction specifications. The tubingmay be selected for chemical, temperature, and physical constraints. Thewelds, connectors, surface and terminal components may also be tailoredfor similar integrity concerns.

Several methods are employed to move the tubing through a wellbore orpipe. Tractors may be used to provide axial motion. The tubing may havean outlet port that may be configured to vibrate as described above. Thesurface connection may include a component to intentionally vibrate thetubing. The fluid may be introduced to and controlled throughout thetubing to tailor at its flow and the resulting tubing vibration usingvalves, pumps, and other devices. Embodiments herein provide methods andapparatus to distribute additional vibration along the length of thecoiled tubing and to control the various ways vibration may beintroduced anywhere in the coiled tubing assembly.

To be explicit, a rod that may benefit from embodiments herein may behollow and configured to deliver fluid such as coiled tubing. The rodmay be solid with no voids in its cross section or it may have a narrowinterior hollow void in comparison to its outer diameter. The void maybe circular or ellipsoid or eccentric. A rod may be cylindrical inshape, that is, have a primary length and a circular cross section, butit also may feature a cross section that is ellipsoid, square,rectangular, curved, eccentric or indeterminate in nature. The rod maybe metallic, ceramic, composite, polymer, a combination thereof, or someother material selected for its flexibility and resilience in harshenvironments. A diameter of the rod may be consistent for the length ofthe rod. The diameter may vary over the length of the rod, for example,it may narrow along the length away from the surface. It may telescopealong its length. Further, equipment along the length such asconnectors, welds, or valves may also vary its inner and/or outerdiameter along the length of the rod. In some embodiments, a rod maythat may benefit from embodiments described herein include thedeployment of sensors and/or downhole tools (for example, pressure andsampling tools). A rod may also encompass wireline tools including thetools that travel through horizontal regions of a wellbore.

Similarly, the rod may be introduced into a cylinder such as a wellbore.The wellbore may be vertical, deviated from vertical, horizontal, orsome combination thereof. It may be cased or uncased, in transitionbetween the two or some combination thereof. Also, the cylinder may be apipe. The pipe may connect multiple wellbores such as in offshoreoperations. The cross section of the cylinder may be circular. It mayalso be irregular, ellipsoid, eccentric, or indeterminate along itslength. The cross section may vary along the length of the cylinder withregions that are cased, regions that not cased, regions that areperforated and/or fractured or a combination thereof.

Embodiments described herein use single point or distributed(multi-point or continuous) vibration in order to extend the reach of arod moving through a cylinder. That is, intentionally introducing motionorthogonal to, or parallel to, or rotationally about the forwarddirection of the tubing improves the likelihood that the tubing willtravel through a wellbore instead of succumb to the buckling lock-updescribed above. The vibration is employed in order to delay or avoidthe onset of helical buckling of the coiled tubing string and/or toallow progress into the wellbore in the presence of helically buckledtubing.

Several strategies have been used in order to delay or avoid lock-up.Several different types of vibration are possible. These include:

1) Axial vibration—vibration is induced along the axis of the coiledtubing/wellbore

2) Lateral vibration—vibration is induced orthogonal to the axis of thecoiled tubing/wellbore

3) Torsional—rotational vibration is induced about the axis of thecoiled tubing/wellbore

4) Lateral rotational—rotational vibration induced about an axisorthogonal to the axis of the coiled tubing/wellbore

The vibrations could be used individually or in combination with eachother. The vibrations can be phased in order to optimize theireffectiveness in extending reach. Further, vibration sources could belocated in one or several locations along the length of the coiledtubing. Most straightforward would be locating the vibration source atthe surface (e.g., at the injector head). The vibration source could belocated at or near the end of the CT string (e.g., an element of thebottomhole assembly, tractor, etc.). The vibration source could bedistributed along the length of the coiled tubing. This would eitherneed to be assembled during the manufacturing process or discretelengths of the coiled tubing could be joined by a “connector” elementwhich would house the vibration source. In some embodiments, aself-contained module may include a power source (battery,turbine/alternator), electronics, actuator (rotary, linear, hammerdrill, etc.). Also, the lengths of tubing between sources of vibrationcan be different, having different cross-sectional shapes as needed foroptimization.

For a vibrator to be effective, the oscillations should be of sufficientamplitude and frequency to propagate to the critical locations withinthe wellbore where the likelihood of buckling is higher. In long,extended reach wells, locating the vibration source at an intermediatepoint mid-string of the CT (near the critical location) rather than atthe end with other BHA components, would be advantageous. It will alsobe possible to configure multiple vibration sources in differentlocations on the CT string should it become necessary.

Methods to introduce vibration can be classified in 3 distinctlocations, with different mechanical systems utilized:

1) From surface—this has the advantage of using continuous coiled tubing

a. Axial excitation by modulating the injector speed

b. Torsional excitation by rotating the injector unit back and forthabout the axis of the CT

c. Lateral excitation by moving the injector unit from side to side

2) From downhole end of CT—also has advantage of using continuous coiledtubing

a. Mud motor to convert fluid power into vibration (motor configured toprovide desired amplitude and frequency). The induced vibration can belateral (such as introduced by the whirling of the rotor), axial (suchas introduced by modulating a flow port as the rotor turns), torsional(such as introduced by modulating the pressure drop across the motor),or a combination of those.

b. Use of a series of pressure relief valves (controlled so as toopen/close either totally or partially in a modulated/harmonic fashion)in axial or lateral orientation to pulse the fluid flow

c. Use of a cam or series of cams controlled by a downhole motor(similar to mud motor idea, would require downhole power and electronicsbut would allow better control)

d. Use of linear actuator (axial) controlled by a downhole motor orelectro-magnets

e. Use of hammer-drill actuator

3) From distributed vibration module

a. Placing the vibration source(s) mid-string along the CT length, at anoptimal location along the tubing for both length and vibration,maximizes the benefits of the oscillations and requires thoughtfuldesign of the mechanical components. Vibration could be achieved throughdistributed flow induced vibration actuators.

Some embodiments require a means of connecting discrete lengths of CT tothe module. This connection may be mechanical, electrical, or both. Tofacilitate locating the vibrator mid-string of the CT, some embodimentswill use a jointed-spoolable connector. Some embodiments may alsofeature additional well control barriers to address safety risks.

For example, the shape of the module connecting the sections of coiledtubing could be as needed for specified contact with the wellbore. As anexample embodiment of distributed vibration module, we include a figureof REELCONNECT™ connection system (commercially available fromSchlumberger Technology Corporation of Sugar Land, Tex.), which is aspoolable connector to attach discrete lengths of coiled tubing in FIGS.5B and 5C. Here, we modify this attachment device to include a vibrationmodule which may introduce vibration that is axial, lateral, ortorsional. One of the major advantages of the REELCONNECT™ connectionsystem is that it allows joining of tubing sections without butt-weldingthe ends of the sections, saving significant time and reducing assemblyprocess risks. Vibration devices could also be attached viabutt-welding. In any event, the connection system must be selected towithstand the induced vibration. Two options for sectional connectiondevices are shown in FIGS. 5B and 5C.

A detailed example of a connector-based system is now provided. Toenable connection of a vibrator mid-string of the CT, it will benecessary to use a flush, jointed connector (FIG. 5A). The connectorallows two separate CT strings to be joined together, with the OD thesame as the pipe (flushed) to facilitate passing through conventionalwellhead equipment and handling with the injector. Well site rig-up andwellbore deployment of the assembly would be simplified if the connectorwas “spoolable,” i.e., the two connected CT lengths can be stored on onework reel as a single string length. The purpose of the jointed natureof the connector becomes apparent in the event sequence described below.

a) Connect 2 (or more) lengths of CT using “spoolable” connector andstore into a single work reel

b) Make-up conventional BHA to end of CT string

c) Run CT into well to locate “spoolable” connector above wellhead(below injector)

d) Bleed-off pressure in CT string (downhole checkvalve to hold wellborepressure)

e) With BOP's closed, access “spoolable” connector and disconnectthreaded connection between CT lengths

f) Make-up dual, full-bore ball valve assembly; then vibrator to lowerCT length

g) Make-up upper CT length to vibrator

h) Re-install surface equipment to wellhead

i) Run complete assembly into well.

The threaded joint on the connector permits separation of the assemblyinto halves, with each half remaining connected to the CT stringlengths. This threaded joint is non-rotating, allowing make-up to beaccomplished without turning either the upper or lower CT string. Thedual, full-bore ball valve is a redundancy to ensure proper well controlduring disassembly and equipment rigdown. It is likely that theintegrity of the downhole check valve would be compromised uponcompletion of the intervention, i.e., may not hold back well pressure(FIG. 4).

Distributed mechanisms could also include tractors or rotational devicessuch as mud motors. One possible embodiment of a mechanical system thatcould be included in the connection device is shown in FIG. 6. Thisdevice uses the whirling of the rotor of the Moineau motor as the sourceof lateral vibration.

Another possible embodiment is to use the attachment method to deploydistributed tractors or rotation mechanisms such as mud motors. FIG. 7is a schematic of a general tractor. Tractors enable, if placed atappropriate locations along the string, the reach of coiled tubingsystems to become limitless from a load transfer perspective (thoughpressure drop and flow limitations would limit reach at some length).Rotation of the coiled tubing string in the horizontal section wouldsignificantly decrease the component of friction force in the axialdirection. This would significantly delay the onset of helical bucklingand extend reach. In this situation, it may be desirable to NOT rotatethe BHA—this could be achieved through placement of a swivel joint abovethe BHA. The various mechanisms could also be used in combination. Ifusing multiple rotation mechanisms, it may be desirable to rotatedifferent sections of CT in different directions. Amongst otherbenefits, this would limit the total torsional frictional load.

Another component that could be selected as a connection device is apressure pulse system (Such as POWERPULSE™ which is commerciallyavailable from Schlumberger Technology Corporation or other pulsed powerfluid delivery systems) that periodically opens and closes the main flowto generate pressure pulse on the coiled tubing. A valve that iscontrolled for vibration generated by the pressure drop created bychanges in fluid flow may be selected in some embodiments. To summarize,most downhole vibration devices can be modified to incorporate into theconnection device to form a distributed system.

An additional application of the distributed rotation mechanisms,tractors, and/or vibration modules is deployment of completions(typically, lower completions) in deviated wellbores. Instead ofvibration devices, other embodiments would include the use ofdistributed tractors or rotation mechanisms (e.g., mud motors). Anadditional application of the distributed mechanisms (vibration,tractor, or rotation) is deployment of completions in deviatedwellbores. Currently, such deployments are not possible on coiledtubing, as the frictional loads required to push heavy completions (inaddition to the frictional load of the tubing itself) into the wellboresare too large—the coiled tubing would lock-up. The distributed tractors,vibration modules, and/or rotation mechanisms would significantly reducethe axial friction, allowing coiled tubing to deploy these completions.During deployment, if rotation of a section of the completion is notdesirable it can be achieved by placing a swivel joint above the sectionof the completion to prevent it from rotation. This will savesignificant time/cost as compared to deploying these completion stringson drillpipe. If the coiled tubing were still not able to push in theentire completion, it is possible that the completion could be deployedin stages, each stage short/light enough to be conveyed on CT. Whilethis would require multiple sequences of running in and out of the hole,the speed of running in and out of the hole on CT (as compared totripping in/out on drillpipe) may justify this deployment method.

Overall, tailoring relative motion of the rod with respect to therelatively rigid cylinder is desirable. Additional devices may beappropriate for some embodiments. A magnet based system using two setsof magnets that are made to rotate relative to each other and convertthe rotation into a modulated axial force may be desirable for someembodiments as it minimizes the effect on the fluid flow. Anagitator-based system with openings that are designed to open and closein a modulated fashion and are distributed across the circumference ofthe rod may be desirable for some embodiments. The surface of the rodmay be modified to create a wave-like disturbance along the length ofthe tubing as the fluid goes through.

Control may be helpful, such as synchronization of or tailoring forvibration decay along the length of the tubing for multiple vibrationmodules. Appropriately synchronizing vibration may use sensing deviceslocated along the length of the CT string (either in the vibrationmodules, in a fiber optic cable, or through other means) to sense theexcitation state of the string. The distributed vibration modules mayalso include sensors to monitor wellbore conditions. The informationfrom the various sensors could be communicated via fiber optic cable(iCoil), wirelessly, through an electrical cable, or other means. Basedon the sensor information, downhole actuation of the vibrationmechanisms can be adjusted to control the synchronization of the variousvibration mechanisms (for example, by adjusting the flow into avibration mechanism).

An additional embodiment includes sensors in these vibration modules inorder to both extend reach through vibration and monitor conditions inthe wellbore through the sensors. The sensors could include pressure,temperature, vibration such as accelerometers and gyros,tension/compression through strain gauges or other means, and/or fluidmonitoring. Another embodiment includes the sensors without thevibration modules when reach extension is not required, for example. Anembodiment with vibration/sensor modules is depicted in FIG. 8.

In some embodiments, it is desirable for the vibration source to be“on/off” switchable, i.e., vibrations are only produced when pumpingduring the critical stages of the RIH process. This will ensure that itdoes not interfere with or is “invisible” to the intended objective ofthe intervention (e.g., pumping acid, wellbore cleanout, etc.) once thetarget depth is reached. Simply, the vibration effects are only requiredduring conveyance. Essentially, the tool has two modes: vibration modeand normal operation mode. The function can be switched from vibrationto operation mode by pumping at a certain threshold rate. If necessary,it can be shifted back to vibration from operation mode by the samemeans. The chart (FIG. 8) schematically shows the correlation betweentool modes, pressures and pump rate.

An additional control component includes acknowledging that thevibration tool will generate an oscillating axial force when pumping ata certain pump rate. This pump rate is predetermined per the jobrequirement, but it is adjustable at surface prior to running the toolinto the wellbore. The magnitude and frequency of the oscillating forceis adjustable as well, predetermined through modeling analysis beforeRIH. This ensures that the proper oscillations are developed for a givenwellbore/CT configuration. The adjustability can be accomplished atsurface prior to running the tool into the wellbore and need notnecessarily be adjustable “on-demand” when the tool is in the wellbore.

In some of the embodiments explained above, the only component thatwould require a “spoolable” feature would be the connector itself. Therest of the assembly, such as a dual ball valve and vibrator, may beconventionally constructed as with other bottom hole assemblies.Furthermore, because these are assembled below the stripper (WHP packoffseal), an OD flushed with the CT diameter is not a requirement.

The advantages of some of the embodiments herein are numerous. Coiledtubing operations and pipe maintenance programs including clearing pipesgenerally could benefit from this. Long distance tubing may be a benefitfor some embodiments. Using the tubing for operations that traditionallyrequire more rigid pipe-like equipment is a benefit. Embodimentsdescribed herein could also enable deployment of stiff, heavy lowercompletions in deviated wellbores.

We claim:
 1. A method for delivering a rod in a cylinder, comprising:propagating a rod in a cylinder along the interior of the cylinder; andintroducing a motion to a length of the rod, wherein the motion is notparallel to the length of the cylinder and wherein the introducingoccurs along the length of the rod.
 2. The method of claim 1, whereinthe motion comprises at least one motion source along the length of therod.
 3. The method of claim 1, wherein the rod exerts an axial load atits terminal end.
 4. The method of claim 1, wherein the introducedmotion is selected from the group consisting of in an orientationorthogonal to the length of the rod, in an orientation parallel to thelength of the rod, in an orientation that is rotational with regard tothe length of the rod, and a combination thereof.
 5. The method of claim1, wherein the at least one motion sources comprise a control systemthat controls at least one of the motion sources.
 6. The method of claim1, wherein the motion sources comprise a vibration source, a tractor, amud motor, a pressure relief valve, a pressure pulse system, or acombination thereof.
 7. The method of claim 1, wherein the multiplemotion sources comprise a control system in communication an individualmotion source.
 8. The method of claim 7, wherein the control systemcomprises sensing location information about the rod, communicating theinformation, comparing the information to a model, and actuating theindividual motion source.
 9. The method of claim 8, wherein the model isbased on cylinder information.
 10. The method of claim 1, wherein therod is a component of a spooled conveyance.
 11. The method of claim 10,wherein the spooled conveyance comprises coiled tubing.
 12. The methodof claim 1, wherein the cylinder is a wellbore in a subterraneanformation.
 13. The method of claim 12, wherein the rod is a coiledtubing system.
 14. The method of claim 1, further comprising controllingthe multiple motion sources to tailor the frictional contact betweensurfaces of the rod and the cylinder.
 15. The method of claim 1, furthercomprising introducing a second motion along the length of the cylinder.16. An apparatus for delivering a rod in a cylinder, comprising: a rodcomprising a length within the cylinder; and at least one motion sourcepositioned along the length of the rod.
 17. The apparatus of claim 16,wherein a control system is in communication with one of the motionsources.
 18. The apparatus of claim 17, wherein the control systemsynchronizes the operation of one of the motion sources.
 19. Theapparatus of claim 17, wherein the control system is housed at thesurface.
 20. The apparatus of claim 17, wherein the control system ishoused along the length of a rod.
 21. The apparatus of claim 16, whereinthe motion source is a valve.
 22. The apparatus of claim 16, wherein therod comprises a spooled conveyance.
 23. The apparatus of claim 22,wherein the conveyance comprises coiled tubing.
 24. The apparatus ofclaim 23, wherein the tubing comprises metal, polymer, ceramic, orcomposite.
 25. The apparatus of claim 16, further comprising sensorsand/or pressure tools and/or sampling tools.
 26. The apparatus of claim16, further comprising a control system and at least one second motionsource and wherein the motion sources comprise a vibration source. 27.The apparatus of claim 26, wherein the vibration source providesvibration that is axial, lateral, torsional and/or lateral.
 28. Theapparatus of claim 26, wherein the control system controls the motionsources individually.
 29. The apparatus of claim 26, wherein the controlsystem controls the motion sources collectively.
 30. The apparatus ofclaim 29, wherein the control system optimizes the vibrations inrelative phase to each other.
 31. The apparatus of claim 16, whereindiscrete lengths of the rod are joined by a connector.
 32. The apparatusof claim 16, further comprising a connector which houses a vibrationsource.
 33. A method for delivering a rod in a cylinder, comprising:propagating a rod in a cylinder along the interior of the cylinder; andintroducing a motion to a length of the rod; and wherein the motioncomprises at least one motion source along the length of the cylinder.34. The method claim of 33, wherein the introduced motion is in anorientation orthogonal to the length of the cylinder.
 35. The methodclaim of 33, wherein the introduced motion is in an orientation parallelto the length of the cylinder.
 36. The method claim of 33, wherein theintroduced motion is rotational to the cylinder.
 37. The method claim of33, wherein the at least one motion source comprises a control system tocontrol at least one of the motion source.
 38. An apparatus fordelivering a rod into a cylinder, comprising: a rod comprising a lengthwithin a cylinder wherein the cylinder comprises at least one motionsource positioned along the length of the cylinder.
 39. The apparatus ofclaim 38, further comprising a control system in communication with atleast one of the motion sources.
 40. The apparatus of claim 39, whereinthe control system synchronizes the operation of one of the motionsources.
 41. The apparatus of claim 39, wherein the control system ishoused at the surface.
 42. The apparatus of claim 39, wherein thecontrol system is housed along the length of a rod.
 43. The apparatus ofclaim 38, wherein the motion source is a valve.
 44. The apparatus ofclaim 38, wherein the rod comprises a spooled conveyance.
 45. Theapparatus of claim 44, wherein the conveyance comprises coiled tubing.46. The apparatus of claim 45, wherein the tubing comprises metal,polymer, ceramic, or composite.
 47. The apparatus of claim 38, furthercomprising sensors and/or pressure tools and/or sampling tools.
 48. Theapparatus of claim 38, further comprising a control system and at leastone second motion source and wherein the motion sources comprise avibration source.
 49. The apparatus of claim 48, wherein the vibrationsource provides vibration that is axial, lateral, torsional and/orlateral.
 50. The apparatus of claim 48, wherein the control systemcontrols the motion sources individually.
 51. The apparatus of claim 48,wherein the control system controls the motion sources collectively. 52.The apparatus of claim 51, wherein the control system optimizes thevibrations in relative phase to each other.
 53. The apparatus of claim38, wherein the rod comprises discrete lengths joined by a connector.54. The apparatus of claim 38, wherein the connector houses a vibrationsource.